Heavy oil wells produce oil by depletion from hot formations. Insulation of the oil is required to prevent an increase in oil viscosity due to cooling of the oil during its way to the surface.
The rate of oil production from a heavy oil well can be increased by injecting high pressure steam both into the well and outwardly into the oil reservoir. This procedure heats the fluids in the well and causes an increase in pressure due to thermal expansion of the crude oil. Furthermore, the heating of the oil also causes the lowering of the oil viscosity. Steam usually is injected for a time period that may range from a few days to a month or more. Thereafter, the steam injection is stopped, and the pressure within the well is reduced to cause flow from the reservoir into the well. When the rate of flow of oil from the reservoir into the well diminishes to a level close to the rate of flow for the cold oil, the steam injection is repeated to heat the reservoir again. In this manner, the mobility of the oil that has moved from remote portions of the reservoir to the vicinity of the well is increased and more oil can be recovered.
Several problems have been encountered when practicing the foregoing steam stimulation processes. The most significant of these is the damage to the well casing that results when heat is transferred through the annulus from the well tubing to the casing as the steam flows down the well through the well tubing and overheats the casing. The attendant thermal expansion of the casing may break the bond between the casing and the surrounding cement causing steam leakage between the casing and the oil well wall, casing buckling or failure due to thermal stress. The second significant problem is the loss of thermal energy when the heat transfer takes place between tubing and casing. This results in a poor quality steam at the bottom of the well, and the possibility of having only hot condensate at the bottom of the well. Other problems are the difficulties encountered in placing adequate insulation inside deviated and inclined oil wells, and in insulating very narrow wells.
U.S. Pat. No. 3,618,680 to Jacocks, describes a liquid insulating medium for use in insulating thermal injection wells, wells drilled through permafrost, and pipelines which traverse a permafrost region. The disclosed medium comprises a mineral oil containing from about 1% to about 10% by weight of a fibrous finely-divided magnesium silicate or asbestos. Such an insulating medium is very expensive due to the cost of the highly refined mineral oil used. Additionally, when the magnesium silicate or asbestos concentration in this medium is increased, a very viscous medium results. This makes its placement within an annular space difficult.
U.S. Pat. No. 3,642,624 to Howland et al. describes a thermal insulating fluid for use in the tubing-casing annulus of steam injection wells. The fluid is composed of heavy mineral oil, preferably having an API gravity of less than 30 degrees, a bentonite-organic base compound, and finely divided asbestos fibers. The composition includes soap-forming ingredients, specifically lime and fatty acids, which react adjacent to the steam injection tubing to form a coating of soap on the tubing and to form a gel after the injection of the steam begins. Although this fluid may perform satisfactorily, this type of liquid insulation is also very expensive. Besides, in case of contact with high quantities of water, the coating of soap that is present will be dissolved by the excess of water; as a result the thermal insulating properties of the fluid will diminish.
U.S. Pat. No. 3,831,678 to Mondshine discloses a composition containing organophilic clays together with asbestos as a gelled oil-based packer fluid for wells drilling through permafrost.
The thermal insulating fluid of the present invention overcomes, or at least minimizes, the aforementioned drawbacks of the prior art compositions.